Bitumen is a thick, sticky form of crude oil, so heavy and viscous (thick) that it will not flow unless heated or diluted with lighter hydrocarbons. At room temperature, bitumen is much like cold molasses. Often times, the viscosity can be in excess of 1,000,000 cP.
Due to their high viscosity, these heavy oils are hard to mobilize, and they generally must be made to flow by adding heat in order to produce and transport them. One common way to heat bitumen is by injecting steam into the reservoir. Steam Assisted Gravity Drainage (SAGD) is the most extensively used technique for in situ recovery of bitumen resources in the McMurray Formation in the Alberta Oil Sands.
In a typical SAGD process, shown in FIG. 1, two horizontal wells are vertically spaced by 4 to 10 meters (m). The production well is located near the bottom of the pay and the steam injection well is located directly above and parallel to the production well. In SAGD, a “startup” or “preheat” period is required before production can begin. The typical startup lasts 3-6 months, and during that time, steam is injected continuously into both wells until the two wells are in fluid communication. At that time, the lower well is converted over to a producer, and steam is injected only into the injection well, where it continues to rise in the reservoir and form a steam chamber.
With continuous steam injection, the steam chamber will continue to grow upward and laterally into the surrounding formation. At the interface between the steam chamber and cold oil, steam condenses and heat is transferred to the surrounding oil. This heated oil mobilizes and drains, together with the condensed water from the steam, into the production well due to gravity.
This use of gravity gives SAGD an advantage over conventional steam injection methods. SAGD employs gravity as the driving force and the heated oil remains warm and mobile when draining toward the production well. In contrast, conventional steam injection displaces oil to a cold area, where its viscosity increases and the oil mobility is again reduced.
Conventional SAGD tends to develop a cylindrical steam chamber with a somewhat tear drop or inverted triangular cross section. With several SAGD well pairs operating side by side, the steam chambers tend to coalesce near the top of the pay, leaving the lower “wedge” shaped regions midway between the steam chambers to be drained more slowly, if at all. Operators may install additional producing wells in these midway regions to accelerate recovery, as shown in FIG. 2, and such wells are called “infill” wells, filling in the area where oil would normally be stranded between SAGD well-pairs.
Although quite successful, SAGD does require enormous amounts of water in order to generate a barrel of oil. Some estimates provide that 1 barrel of oil from the Athabasca oil sands requires on average 2 to 3 barrels of water (cold water equivalent), although with recycling the total amount can be reduced to 0.5 barrel. In addition to using a precious resource, additional costs are added to convert those barrels of water to high quality steam for downhole injection. Therefore, any technology that can reduce water or steam consumption has the potential to have significant positive environmental and cost impacts.
Another problem with steam-based methods is that they may not be appropriate for use in the Artic, where injecting large amounts of steam for years on end has high potential to melt the permafrost, allowing pad equipment and wells to sink, with potentially catastrophic consequences. Indeed, the media is already reporting the slow sinking of Artic cities due to global warming, and cracking and collapsing homes are a growing problem in cities such as Norilsk in northern Russia.
Therefore, although beneficial, the SAGD concept could be further developed to address some of these disadvantages or uncertainties. In particular, a method that reduces steam use would be beneficial, especially for Arctic tundra environments, where steam based methods may be hazardous or impractical.